One of the primary methods for well stimulation in the production of hydrocarbons is hydraulic fracturing. Hydraulic fracturing is a method of using pump rate and hydraulic pressure to fracture or crack a subterranean formation. Once the fractures are made, high conductivity proppant is pumped into the fracture via fracturing fluid to prop open the cracks. When the pump rates and pressures are reduced or removed from the formation, the fracture cannot close or heal completely because the high conductivity proppant props the fracture open. The propped fractures provide a high conductivity path connecting the producing wellbore and a larger formation area to enhance the production of hydrocarbons.
The recovery of hydrocarbons from a subterranean formation leaves a substantial amount of the initial hydrocarbons still in the formation. During the production of desirable hydrocarbons such as crude oil and natural gas, a number of other naturally occurring substances may also be encountered within the subterranean environment.
The removal of unwanted deposits from the wellbore and production equipment is generally referred to as “remediation.” In contrast, the term “stimulation” generally refers to the treatment of geological formations to improve the recovery of hydrocarbons. Common stimulation techniques include hydraulic fracturing, acidizing, and coiled tubing operations. Well remediation and stimulation are important services that are offered through a variety of techniques by a large number of companies.
Oil and natural gas are found in, and produced from, porous and permeable subterranean formations. The porosity and permeability of the formation determine its ability to store hydrocarbons and the facility with which the hydrocarbons can be extracted from the formation.
Both porosity and permeability are geometric properties of a rock, and both are the result of its lithological (composition) character. A rock with pores is referred to as porous. This means it has tiny holes through which oil may flow. Reservoir rocks must be porous, because hydrocarbons can occur only in pores. A suitable reservoir rock must therefore be porous, permeable, and contain enough hydrocarbons to make it economically feasible for the operating company to drill for and produce them.
Capillary pressure is important in reservoir engineering because it is a major factor controlling the fluid distributions in a reservoir rock. Capillary pressure is only observable in the presence of two immiscible fluids in contact with each other in capillary-like tubes. The small pores in a reservoir rock are similar to capillary tubes and usually contain two immiscible fluid phases in contact with each other. Thus capillary pressure becomes an important factor to be considered when dealing with reservoir rocks.
The larger the pore radius, the lower the capillary pressure is. Low capillary pressure and low irreducible water saturation are associated with reservoir rocks that have large pores, such as coarse-grained sand. It naturally follows that high capillary pressure and high water saturations are associated with fine grained reservoir rocks. As a result, in tight formations the capillary pressure will be high. It is difficult to produce the hydrocarbon without reducing the capillary pressure. Removing water from pores is critical to reducing the capillary pressure.
Thus, if a fracturing fluid formulation can effectively reduce the water saturation within fine grained reservoir rocks, it will provide greater oil/gas productivity in this kind of subterranean formation.
The use of certain microemulsion additives during completion of both oil and gas wells leads to higher permeability and long-term increased production of hydrocarbons from the well. The increased displacement of water from the formation and proppant by both oil and gas (flowback) and consequent increased production of hydrocarbons have been attributed to lowered capillary pressure. In porous media, capillary pressure is the force necessary to squeeze a hydrocarbon droplet through a pore throat (works against the interfacial tension between the oil and water phases) and is higher for smaller pore diameters. Lowered capillary pressure may also lead to higher gas/oil permeability of subterranean formations. However, previous solvent-hydrocarbon surfactant systems have limitations in their ability to lower capillary pressure, especially for fine grained reservoir rocks. There is, therefore, a need for treatment compositions that are capable of lowering capillary pressure and the water saturation within reservoir formations while maintaining the desirable properties of conventional emulsified treatment formulations.
The types and uses of fracturing fluids have evolved greatly over the past 70 years and continue to evolve. The U.S. oil and gas industry has utilized fluids for fracturing geologic formations since the early 1940s. Available scientific literature indicates that hydraulic fracturing fluid performance became a prevalent research topic in the late 1980s and the 1990s. Most of the literature pertaining to fracturing fluids relates to the fluids' operational efficiency rather than their potential environmental impacts.
Although a number of microemulsion compositions are known in the prior art, such as MA-844W, which is developed by CESI Chemical and disclosed in U.S. Pat. No. 7,380,606, it is a flammable liquid due to the higher quantity of organic solvents in the composition and the lower flash point, i.e., 25° C. (see https://www.cows.bz/Assets/pdfs/tds-acid/MA-844W%20Micro%20Emulsion%20%TDS.pdf).
Thus, there is a continued need for more effective and also environmentally preferable compositions for formation stimulation, remediation, and drilling operations.